Natural gas is a resource which is available from several locations around the world, some of which are ‘remote’ from a suitable processing environment, and/or some of which are ‘off-shore’. It is often desirable to process and liquefy natural gas for use of the natural gas in another location, for a number of reasons. As an example, natural gas can be stored and transported over long distances more readily as a liquid than in gaseous form, because it occupies a smaller volume and does not need to be stored at a high pressure.
Liquefying natural gas to form transportable liquefied natural gas (LNG) can be carried out at a suitable LNG plant or facility. However, the source of the natural gas and the location of the LNG plant or facility may be in two different locations, for example where the source of the natural gas is offshore. Thus, it is sometimes desirable for the natural gas to be carried over a distance by a pipeline from a source to a processing facility such as an LNG plant.
In addition to methane, natural gas usually also includes some water and hydrates. However, such compounds can corrode a pipeline running between a source and an LNG plant. In the Paper No 05278 in Corrosion 2005 (Houston, Tex.: NACE International, 2005), there is described the problem of ‘top of the line corrosion’ in wet gas transportation, as the water vapor condenses on the internal walls of the pipeline due to the heat exchange occurring between the pipeline and its surroundings (e.g. offshore or arctic production). Water vapor condenses on the colder walls, forming a thin film of liquid which is enriched in aggressive species, such as organic acids and carbonic acid which comes from the dissolution of carbon dioxide.
Thus, and as further described in this Paper, monoethylene glycol is often added in the transportation of wet gas in order to prevent the formation of hydrates which can plug the pipeline. It is also known that glycol has a strong effect on carbon dioxide corrosion mainly because it affects the solubility of carbon dioxide in the liquid phase. This Paper also discusses that control of pH is also a common corrosion mitigation method. Thus, one or more pH regulators can also be added to the natural gas in order to help reduce and/or prevent corrosion in the pipeline.
At the LNG plant or facility, such additives then need removal from the natural gas stream. General removal of additives from a multiphase flow can be carried out by a gas/liquid separator. However, whilst it is hoped that such a separator will remove 100% of the additives prior to further processing of the gas stream, in practice, it has been found that a small amount of additive(s) remains with the gas stream after the separation. This results in such remaining additives being taken into the next processing steps of the gas stream, such as the removal of impurities and heavy hydrocarbons. Whilst the amount of the remaining additive(s) in the gas stream may be relatively small, it can build up over time to affect for example the solvent(s) used in the next processing step(s). The remaining additives can also pass into the intended chemical or physical transformation processes (for example liquefaction or a Fischer-Tropsch process), where its presence creates an undesired product. For example, liquefied glycol can lead to blockage of filters and blockage of small diameter parts of a liquefaction apparatus.
It is an object of the present invention to reduce and/or minimize the amount of additives remaining in a hydrocarbon stream (after having been added to the hydrocarbon stream to assist its passage from one location such as its source, to another location such as an LNG plant or facility, and) prior to further processing of the hydrocarbon stream.